Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drives oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques extend a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place. Enhanced oil recovery, or EOR, is a generic term encompassing techniques for increasing the amount of crude oil that can be extracted from a subterranean formation such as an oil field.
However, after much of the easy-to-produce oil is recovered from an oil field, tertiary recovery, or enhanced oil recovery (EOR), techniques offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place. Three major categories of EOR have been found to be commercially successful to varying degrees:
Thermal recovery—the introduction of heat such as the injection of steam to lower the viscosity of the oil, and improve its ability to flow through the reservoir.
Gas injection—injection of gases such as natural gas, nitrogen, or carbon dioxide that expand in a reservoir to push additional oil to a production wellbore, or gases that dissolve in the oil to lower its viscosity and improve flow rate.
Chemical injection—injection of polymer dispersions to increase the effectiveness of waterfloods, or the use of detergent-like surfactants to help lower the surface tension that often prevents oil droplets from moving through a reservoir. Chemical injection of a polymer is also referred to as polymer flooding. This method improves the vertical and areal sweep efficiency as a consequence of improving the water/oil mobility ratio. In addition, the polymer reduces the contrasts in permeability by preferentially plugging the high permeability zones flooded by polymers. This forces the water to flood the lower permeability zones and increases the sweep efficiency. The art in this area is well-developed for conventional oil recovery applications.
However, finding and producing new hydrocarbon reserves involves contending with increasingly harsh downhole conditions. In the past, the challenging environments of High Pressure/High Temperature (HP/HT) wells were considered uneconomic. However, as technologies evolved, tapping these reservoirs became an economic reality. An HP/HT well is considered so when the conditions of the well are hotter or more pressurized than conventional wells. In many HP/HT wells, the bottomhole temperature (temperature at the total depth of the well) is 100° C. or higher, for example 120° C. to 170° C. In some deep North Sea reservoirs, condensate gases have been found at temperatures up to 190° C. and pressures up to 1100 bar. These conditions are combined in a subterranean environment that includes fresh water, brackish water, or seawater.
As long as these fields have large enough reservoirs, the development of HP/HT wells is expected to continue. However, the harsh conditions encountered inside such reservoirs present a challenge for suppliers of equipment and materials for these operations. Operators can be expected to continue pushing the boundaries of operable methodology in order to replace more easily obtained reserves in all types of oil recovery operations. And materials injected during polymer flooding may reside inside a reservoir at elevated temperatures for months, being subjected to these harsh conditions for as long as two years. As a result, there is a need in the industry to develop technologies suitable for carrying out enhanced oil recovery in conjunction with the challenging conditions encountered in HP/HT wells. Conventional polymers used for EOR, for example, are hydrolytically unstable in high temperature conditions, such as temperatures over 100° C. Hydrolysis or other deleterious reactions lead to permanently lowered viscosity and even precipitation of these polymers during use.
Organic polymers traditionally used in EOR include water soluble polymers such as polyacrylamides, polyacrylates, and hydrophobically modified water soluble polymers, also called associative polymers or associative thickeners. In water or seawater dispersions at temperatures of 100° C. and above, ester and amide functionalities hydrolyze to carboxylic acid or a salt thereof at a rate of hours to weeks depending on conditions such as pH and salt concentration. Consequences of hydrolysis include substantial loss of dispersion viscosity and even precipitation, both of which lead to reduced recovery rates of oil from subterranean formations.
Attempts to compensate for loss of viscosity due to hydrolysis include providing a very high initial viscosity dispersion, such that after hydrolysis is complete a sufficient dispersion viscosity is maintained to carry out EOR. However, the initial viscosity of such dispersions is typically sufficiently high to impede its injection into the subterranean formation. Further, maximum efficiency in polymer flooding is realized by matching the viscosity of the polymer dispersion with the viscosity of the oil in the reservoir; wherein at temperatures above 100° C. the oil in the reservoir may display viscosities as low as 4 cP, for example about 4 to 8 cP.
Thus, there is a substantial need in the industry for polymer compositions that are suitable for use in enhanced oil recovery operations carried out at temperatures of 100° C. or greater.